1. Field of the Invention
The present invention pertains to the treating of oil and gas wells and, more particularly, to the optimization of stimulating the entire interval of an earth formation containing zones of multiple stress gradients.
2. Background
Oil and gas wells are typically constructed with a string of pipe, known as casing or tubing, in the well bore and concrete around the outside of the casing to isolate the various formations that are penetrated by the well. At the strata or formations where hydrocarbons are anticipated, the well operator perforates the casing to allow for the flow of oil and/or gas into the casing and to the surface.
At various times during the life of the well, it may be desirable to increase the production rate of hydrocarbons with stimulation by acid treatment or hydraulic fracturing of the hydrocarbon-producing formations surrounding the well. In a hydraulic fracturing operation, a fluid such as water which contains particulate matter such as sand, is pumped down from the surface into the casing and out through the perforations into the surrounding target formation. The combination of the fluid rate and pressure initiate cracks or fractures in the rock. The particulates lodge into these fractures in the target formation and serve to hold the cracks open.
The increased openings thus increase the permeability of the formation and increase the ability of the hydrocarbons to flow from the formation into the well casing after the fracture treatment is completed.
Within a given formation, the Fracture Gradient is the pressure or force needed to initiate a fracture in the formation by way of pumping a fluid at any rate. The Fracture Gradient for a formation may be calculated from the instantaneous shut-in pressure (“ISIP”). The ISIP is an instant pressure reading obtained when the operator pumps a fluid at a desired rate then abruptly decreases the pump rate to zero and instantaneously reads the pump pressure. The pressure reading at zero pump rate is the ISIP.
In relatively thin formations that are fairly homogeneous, the above referenced standard fracturing technique will normally produce a fracture or fractures throughout the depth of the formation. However, when an operator attempts to fracture a large formation having multiple zones of varying stresses and different Fracture Gradients in a normal fracture treatment, the fracture fluid tends to dissipate only into those portions of the formation having the lowest Fracture Gradient and the lowest stress gradient. Thus, the fracture treatment may only be effective in a small portion of the overall target formation.
One solution to this problem is fracture treating the large formation in multiple stages. This solution is both more costly and more time consuming than a traditional single-stage fracture treatment. Other options include utilizing specialized equipment to simultaneously fracture treat an entire formation as is described in U.S. Pat. No. 6,644,406. That solution is also more expensive because it requires the use of specialized equipment.
Another solution known as “limited entry” is to introduce more perforations through the casing in intermediate zones having higher rock stresses and fewer perforations through the casing in intermediate zones having lower rock stresses. A typical fracture treatment would theoretically stimulate all intermediate zones at the same time. However, this process requires more knowledge of the rock properties than is typically available from the well log and thus requires additional testing to insure that the optimum number of perforations are spaced within the zones.
During fluid treatment of a well, particularly when treating a large formation in multiple stages, it may be desirable to divert the flow of fluids through some, but not all, of the well casing perforations. The use of ball sealers for this purpose is well known in the industry and is described in numerous patents, including U.S. Pat. No. 4,505,334 and U.S. Pat. No. 4,102,401. Ball sealers are typically small rubber-coated balls that are pumped into the well casing and onto the perforations by the flow of the fluid through the perforations into the formation. The balls seat upon the perforations and are held there by the pressure differential across the perforation.
Ball sealers are commonly used in the field of oil and gas well treatment to create diversion. Diversion is the forced change of the path of fluid while the fluid is being pumped into a formation. Ball sealers are commonly used in acid treatments, which are pumped at lower rates than fracture treatments. Many engineers are uncomfortable using ball sealers in fracture treatments because of the higher pumping rates.
Conventional determination of a diversion caused by ball sealers in any fluid treatment is made by observing any “surface” changes in the Standard Treating Pressure (“STP”). For example, if an engineer is pumping an acid job at 5 barrels per minute (“bpm”) with an STP of 1200 pounds per square inch (“psi”), the engineer will watch for any pressure deviation on the surface from the STP of 1200 psi to determine if the ball sealers are diverting the acid to unstimulated rock. A problem with this conventional procedure is that observing surface pressure changes is not a reliable means for determining whether fluid is actually being diverted into different rock zones. Small pressure changes caused by diversion are muted by the weight of the hydrostatic column. Thus the only way to accurately confirm that a particular treatment is reaching a particular zone is to know the characteristics of the particular rock zone. One means of doing this is by determining the Fracture Gradient for each different rock zone of varying stress.